Offshore platform FEED

Yutaek Seo

Oil and Gas production

• Hydrocarbon fluids produced from a reservoir are seldom (if ever) suitable for

direct sale to a buyer. These fluids must be conditioned prior to their

disposition.

• Petroleum reservoirs are a mixture of crude oil, natural gas and water. These

constituents are separated and processed to make marketable products.

• The gas conditioning and processing equipment is only a part of the entire

system. The total system may look very much like that shown below.

Figure 1.1 Schematic View of a Total Production Processing System

• For convenience, we divide each system into modules. A dehydration unit, for

example, would be a module; as would a fractionation tower with its auxiliary

equipment.

• The choice of modules is governed by convenience, both for calculation and

decision purposes.

• Unfortunately, one can do a sound job of designing, specifying and operating

each modular unit, but end up with a poor system.

• The reason is that each module has varying characteristics under varying loads

that may result in a type of internal incompatibility. One modular unit may

require a certain incoming analysis to produce the output desired.

• If a previous unit does not maintain this, then the downstream unit may not

prove satisfactory. The fault might not lie so much with that unit but with total

system design.

• Root of most problems

: One is to concentrate on the detailed design of each module without proper

consideration of the total system within which it resides.

: Another is failure to properly recognize the degree of uncertainty in the input

and output specifications of the system, random variables within practical limits.

• The process simulation is nothing more than performing (in advance) those

calculations which characterize system behavior. The most routine form of

simulation simply involves solving the equations which (hopefully) describe the

operation of concern.

• Although we currently do much of this on a computer, it adds nothing to the

value of the result unless greater true precision is obtained.

• Total simulation must recognize formally the uncertainty of the numbers used.

Using an average or most probable analysis is not an answer. These are only

two points on the likely distribution curve (mean and mode respectively).

• Total simulation must include these concerns so that the system may possess

necessary flexibility with minimum use of arbitrary safety factors.

The basic system

• Figure 1.1 represents a fairly complete processing setup for handling produced

fluids. It encompasses almost all systems used.

• Each of the squares shown represents a calculation module. Within this module

there is a body of equations and practice which enables one to design it subject

to the imposed constraints.

• Not shown in the modular setup are the pumps, compressors, valves and

fittings, and lines necessary to move, control and contain the fluids flowing

between modules. These are interconnecting modules difficult to show on

diagrams. (goes to P&ID)

• Some major modules shown have a number of sub-modules representing

component parts that involve some unique and/or separate engineering

concern.

• For example, the NGL extraction module could be subdivided as shown in

Figure 1.2. This figure is for the very simplest form of refrigeration system

consisting of a well stream exchange, refrigeration source, and separation of

liquid from vapor.

Figure 1.2 Refrigeration Type of Liquids Recovery Module

• The production operation does not change the basic system or its needs.

• On one hand, the planner does not always possess the technological expertise

to impose realistic constraints on each individual element in the system.

• On the other hand, the people charged with operating each element resist

change from those practices which have served them well traditionally.

• Handling the system as a system instead of a series of loosely connected

individual functions can lead to a more rational basis for greater net profit.

• Constraints of the basic system

1. The quantity and analysis of fluids entering

2. The market demand (quantity and price) for the effluent products

3. Legal and quasi-legal conditions imposed "no-flare" gas orders, proration, contracts

and agreements, national and political concerns, and the like

4. Environmental factors labor availability and quality, climate, local customs, population

density, availability of utilities and services, and the like

5. The risk tolerance level technological, political and economic

6. The quantity and quality of available data

• There are an infinite number of systems that could be devised to market the

hydrocarbons available for sale in the reservoir (theoretically). Actually, the

choice is limited by a series of practical considerations.

• As a practical matter, the first problem is “Marketing”

: Technological design must not only serve the present market efficiently but possess

sufficient flexibility to accommodate a future market at minimum additional cost.

: For example, many reserves now exist in areas where there is no significant market for

natural gas and natural gas liquids. However, any system design that is incompatible with

future gas processing in these areas is a poor one.

• Total reserves might be the paramount constraint. The maximum capital outlay

that will yield a fair profit is fixed at some point by this concern.

• An uncertain political climate might offer a similar constraint limit the amount of

risk capital to that which will afford both a realistic payout time (to reduce time

risk) and a satisfactory rate of return.

• These overall economic constraints provide the boundaries for our system

“jigsaw puzzle”. One then proceeds to the lower order, but equally important,

legal and quasi-legal restrictions familiar.

: Compressor capacity rather than the reservoir may limit oil production when a "no flare"

order is in effect.

: Fulfillment of a gas marketing contract may require a production schedule that is

"inefficient" from the reservoir viewpoint alone.

The decision modules

The Reservoir Module

• A reservoir study generally is undertaken for one of two reasons: to establish

value or to forecast performance under various production strategies.

• The typical report deals in gross numbers not entirely suitable. Needed is a

special report showing greater detail about the character and condition of

produced oil and gas.

: Based on current samples, compositional balances can be made to forecast changes in

gas and liquid analysis with time.

: Geological data are valuable for judgment decisions involving the extrapolation of

current data number of wells, likelihood of solids production from core data, gathering

system layout, etc.

: Pressure maintenance is used to permit high initial production rates without excess

pressure decline. The injection of water and/or gas usually is involved. At some point in

time these will begin to "break through" into the production wells. Wellhead pressure will

be different; liquid-gas ratios will change. Production/processing system needs will

change accordingly.

: Is the surface system designed to accommodate only current conditions? If so, some

major modifications will be necessary eventually. In an offshore or frontier environment

the cost of modification plus the hidden cost of inefficient production practices can

seriously compromise future profitability and limit reservoir recovery efficiency.

The Separation Module

• With few exceptions, some liquid will be obtained even though the fluid in the

reservoir is all vapor, at reservoir conditions. In this instance, a flash calculation

must be made at separation conditions to obtain the quantity and composition

of all effluent streams.

• If the primary effluent is crude oil or any other liquid stream, containing a

reasonable percentage of heavy hydrocarbon molecules (larger than octane),

this calculation is difficult.

• Gas specific gravity alone is inadequate for subsequent liquid recovery

computations.

• Furthermore, even routine changes in temperature and pressure will affect the

performance of subsequent modules.

Crude Oil Treating Module

• This module is required to meet crude oil sales specifications:

1. BS&W (Basic Sediment and Water)

The BS&W specifications is essentially an entrained water specification. It limits the

amount of free water carried with the crude. It often varies from 0.3% to 3.0% by volume

with the lower number applied to light crudes and the higher number to very heavy

crudes (< 20 API).

2. Vapor pressure

The vapor pressure specification limits the volatility of the crude oil. If the crude oil is

stored or transported at or near atmospheric pressure this specification will often be

equal to or less than 101.3 kPa [14.7 psia] at the system temperature. True Vapor

Pressure (TVP) or Reid Vapor Pressure (RVP).

3. Salt

Salt is removed by mixing the crude with fresh water and removing the resultant water in

a crude oil dehydration module.

4. Sulfur content

Sulfur compounds may be removed by gas stripping, or chemical conversion, or a

combination of the two.

Produced Water Treating Module

• Produced water must be treated in order to meet reinjection or disposal

specifications:

1. Hydrocarbons

The hydrocarbon specification is particularly important if the produced water is

discharged to the sea. For example, in the North Sea the oil content in the discharged

water from an offshore platform is limited to 40 ppm by weight (monthly average).

This specification is typically met by gravity separation, flotation units, centrifugal

separation (hydrocyclones).

2. Free solids

Free solids may require removal if the produced water is to be reinjected into the

reservoir.

Removal methods include gravity separation, filtration and centrifugal separation.

3. Dissolved solids e.g., CaCO3, NaCl, BaSO4, etc.

Dissolved solids must be analyzed to assess their compatibility with connate water in

the reinjection zone or with reinjection water from other sources such as sea water. In

this case, specifications can only be established by detailed sampling and testing of

the streams involved.

Gas Processing Module

• Natural gas must also be processed to meet basic specifications prior to its

sale. These include water content, hydrocarbon dewpoint, sulfur content and

heating value.

• The gas processing techniques depends on the composition of the gas, product

specifications and the markets for natural gas and natural gas liquids (NGLs).

• Gas condition and processing are terms used to describe a variety of processes

which involve the removal of one or more components from a natural gas or

natural gas liquids (NGL) streams.

• Gas processing is sometimes generically used for any equipment required to

make the produced gas marketable.

: includes compression, dehydration, sweetening, impurity rejection / recovery (nitrogen,

helium, etc.) and NGL extraction.

• In this manual, we will divide gas processing into two categories:

: Gas Conditioning will refer to the dehydration, impurity rejection / recovery and

sweetening of produced gas.

: Gas Processing will refer to NGL extraction.

Factors affecting gas processing schemes

1. Reservoir conditions - fluid composition, temperature, pressure

2. Field development plan - volumes, temperatures, pressures

3. Legal restrictions - no-flare orders, contracts, nominations, etc.

4. Environmental factors - field location, labor, local customs, etc.

5. Markets - natural gas, NGL, sulfur, and C02 market availability, quantity, price

6. Product specifications (gas) - water and hydrocarbon dewpoint, H2S, heating value

7. Product specifications (NGL) - vapor pressure, water content, H2S and C02

8. Economic - profitability of treatment process

9. Political - national interests such as resource conservation

10. Processing agreements - for NGL extraction

• While all of the above items are critical to an effective design, four factors which

warrant more emphasis are

1) fluid composition,

2) gas contracts and specifications,

3) NGL contracts and specification, and

4) Processing agreements.

Examples of gas composition in the U.S.

Contract terms

Gas contract quality1. Minimum, maximum, and nominal delivery pressure

2. Maximum water content (expressed as a dewpoint at a given pressure)

3. Maximum condensable hydrocarbon content expressed as a hydrocarbon dewpoint

4. Maximum delivery temperature

5. Allowable concentration of contaminants such as H2S, carbon disulfide, mercaptans, etc.

6. Minimum and maximum heating value

7. Cleanliness (allowable solids concentration)

• These quality specifications are extremely important factors in the selection of

the gas treatment process.

• Quality specifications for gas handled by transmission and distribution

companies vary from country to country.

• In a number of instances specifications have been set for historic reasons

rather than technical reasons.

• Table 2.4 provides a comparison between the U.K., North America, and Middle

East specifications.

Liquid contract quality specifications

• Products from natural gas - Natural gas liquids (NGLs) consist of all

hydrocarbons heavier than methane which can be extracted from a natural gas

stream.

• A list of NGL products is provided below:

1. C2 Ethane

2. C3 Propane

3. iC4 iso-butane

4. nC4 normal-butane

5. C5+ Pentanes and heavier

• Liquid contracts usually contain the following basic considerations:

1. Quality of products expressed as vapor pressure, relative or absolute density, or by

standard designation such as Commercial Propane

2. Specifications such as color, concentration of contaminants, etc., as determined by

standard tests

3. Maximum water content

• NGL components normally found in natural gas and the resulting NGL products.

• NGL productsNatural gasoline : mixed product whose basic specification is vapor pressure

Reid vapor pressure: 70-235 @a [lo-34 psia]

Percentage evaporated at 60°C [ 140"FI: 25-85%

Percentage evaporated at 135°C [275"F]: not less than 90%

Corrosion: not corrosive by specified test

Color: not less than plus 25 (Saybolt)

Water content: no free water

Commercial ethane : chemical feed stock for the manufacture of plastics

Demethanized mixes : containing ethane, propane, butane, and natural gasoline (true vapor

pressure 600 psia at 100°F)

Commercial propane : at least 95% propane (true vapor pressure not exceed1.43 MPa(g)

[208 psig] at 38°C [100°F])

Propane HD-5 : special grade of propane for motor fuel (true vapor pressure of more than

1.43 MPa(g) [208 psig] at 38°C)

Commercial butane : predominantly butanes (true gauge vapor pressure not greater than

483 kPa(g) [70 psig] at 38°C [100 °F])

Butane-propane mixtures : sold for domestic heating service or used for secondary

recovery of oil (vapor pressure of the commercial product seldom exceeds 860 kPa(g) [125

psig] at 38°C [100°F])

Vapor pressure

• Vapor pressure specifications may be expressed in terms of a TVP (True Vapor

Pressure) or RVP (Reid Vapor Pressure).

• The vapor pressure or volatility specification is probably the most important

factor determining the ultimate amount of NGLs recovered and the type of NGL

process selected.

• The vapor pressure of an NGL product can be estimated from the following

equation:

𝑃𝑣𝑚𝑖𝑥 = 𝑥𝑖 𝑃𝑣𝑖

𝑃𝑣𝑚𝑖𝑥 = vapor pressure of the NGL mixture

𝑥𝑖 = mol fraction of each component in the mixture

𝑃𝑣𝑖 = vapor pressure of each component in the mixture

• This equation simply says that the vapor pressure of an NGL mixture is

proportional to the vapor pressure and amount of each individual component in

the mixture.

• For specification purposes, vapor pressures are almost always expressed at a

temperature of 38°C [100°F].

• Physical properties of several NGL components (SI)

• Physical properties of several NGL components (FPS)

• Example: Estimate the true vapor pressure (TVP) of an NGL mixture with the

following composition.

mol%

C3 30

nC4 20

nC5 20

nC6 30

total 100

Component xi Pvi Xi Pvi

C3 0.30 13.41 4.02

nC4 0.20 3.77 0.75

nC5 0.20 1.16 0.23

nC6 0.30 0.373 0.11

1.00 5.11 bar

• This is an extremely important concept in the design and operation of NGL

facilities.

• We want the extraction and stabilization processes to be selective. This means

we want to drive out as many of the highly volatile components as possible from

the liquid product while retaining the less volatile components.

• The highly volatile components raise the vapor pressure of the product

unnecessarily and reduce the “room” (in terms of vapor pressure) for the less

volatile components.

• The following example indicates this concept.

• Example: An NGL product must be stabilized to meet a TVP

specification of 3.5 bar abs [50 psia] at 38°C [10O0F].

The unstabilized product has the following composition:

What percent of the unstabilized feed can be recovered as liquid product if

a) no C2 remains in the liquid product?

b) 2% C2 remains in the liquid product?

mol%

C2 10

C3 25

nC4 20

nC5 10

nC6 35

• No ethane in product

(1) (2) (3) (4) (5) (6)

Component Mol

fraction

Pv, pisa Product,

mols

Product,

Mol %

(3) * (5)

Ethane 0.10 800

Propane 0.25 188 13.70 17.41% 32.73

n-butane 0.20 51.74 20.00 25.41% 13.10

n-pentane 0.10 15.575 10.00 12.71% 1.98

n-hexane 0.35 4.96 35.00 44.47% 2.21

1.00 78.70 100.00% 50.02 psia

• 2% ethane in product

• effect of the selectivity of the stabilization system upon product recovery.

: If the stabilization system allows a mere 2% ethane in the liquid product, the product

rate decreased by almost 10%. (78.70 → 72.29 mols)

: The small amount of ethane in the product contributes over 30% of vapor pressure.

(16.00/50.00 psia)

(1) (2) (3) (4) (5) (6)

Component Mol

fraction

Pv, pisa Product,

mols

Product,

Mol %

(3) * (5)

Ethane 0.10 800 1.45 2.00% 16.00

Propane 0.25 188 5.84 8.08% 15.19

n-butane 0.20 51.74 20.00 27.67% 14.26

n-pentane 0.10 15.575 10.00 13.83% 2.15

n-hexane 0.35 4.96 35.00 48.42% 2.40

1.00 72.29 100.00% 50.00 psia

• Two basic types of stabilization systems are employed in oil production and

NGL recovery facilities.

• These are:

1. Flash stabilization - NGL product is flashed to progressively lower pressures. Flash

vapors are recompressed and may be recycled back into the inlet. Heat exchangers may

be used to control the product temperature. The oil-gas separation system on the North

Slope uses this type of stabilization process to meet the TVP specification of the export

crude.

2. Distillation - NGL product is stabilized at constant pressure in a packed or trayed tower.

Temperature is varied from the top to bottom. Stabilizer tower may be refluxed or non-

refluxed (top tray feed). A non-refluxed stabilizer is often used in gas processing plants to

control the vapor pressure of the NGL product mixture.

• The flash stabilization method (1) is the traditional method used in field

processing facilities, especially offshore. It has the advantages of simplicity,

ease of control, and it simplifies topside design.

• Method (2), distillation, is more common in gas processing facilities. It has the

advantages of more selective separation, so product rates are higher. It also

minimizes recompression costs.

Flash stabilization

NGL distillation

• The equipment used in the DPC stabilizer

process simply provides a way to "cook" the

volatile hydrocarbons liquid mix, at the

optimum pressure (50 to 350 psig) and the

required temperature levels (100°F to 400°F).

• This is done in a distillation tower, controlled

in such a way as to drive off the light gaseous

hydrocarbons and other gaseous

contaminants to be used as a fuel stream or

recycled through the conditioning equipment,

eventually to be sold as part of the pipeline

quality natural gas.

• The resulting "stabilized" liquid thereby has a

much-reduced volatility.

NGL market factors

• The natural gas liquids market provides feedstock to the petrochemical and

refining industries and supplies fuel for residential, agriculture, commercial,

power and transportation sectors.

• Understanding the market factors are important in the proper selection of the

NGL extraction technology.

• The disposition of liquids is a primary consideration in determining whether a

dew point control facility is installed (recovering the minimum liquids to meet

pipeline specifications) or if a high liquid recovery facility is constructed.

Natural gas

• The two main uses for natural gas are fuel (residential, commercial, industrial, power

generation, and transportation) and chemical manufacturing feedstock.

• Worldwide, the primary chemicals manufactured from natural gas are methanol and urea

(fertilizer).

Natural gas prices

• The Henry Hub is a distribution hub on the natural gas pipeline system in Erath, Louisiana.

Due to its importance, it lends its name to the pricing point for natural gas futures

contracts traded on the New York Mercantile Exchange (NYMEX)

Ethane

• Ethane is the lightest NGL component. It has one end use – petrochemical feedstock for

the manufacture of ethylene.

• The demand for ethane is a function of the demand and price for petrochemicals and the

price of competing feedstocks (heavier hydrocarbons).

• Since there is only one market for ethane, most ethane may be sold under long

• term contract to a petrochemical buyer.

Propane

• The market for propane liquid is divided between petrochemical feedstock and fuel

(residential, agriculture, commercial, and transportation).

• Propane is often called LPG (Liquefied Petroleum Gas) but the term LPG may also refer to

propane-butane mixtures or a predominately butane stream.

Butane

• The market for butane is primarily petrochemical, gasoline blending, and fuel

• Isobutane is the most volatile isomer and the most valuable. Its primary use is as a refinery

blendstock for the manufacture of high octane components for gasoline.

• Normal butane is an important feedstock for the manufacture of mono-olefins (ethylene,

propylene) and diolefins (butadiene, which is used in the manufacture of synthetic rubber).

• Normal butane may also be isomerized into isobutane. When normal butane is used as a

fuel it is normally blended with propane but it can be used as a pure component.

• The largest use for butane is as a gasoline blending component for octane and vapor

pressure control. As a result of their important gasoline and feedstock uses, butanes are

normally fed to refineries.

Natural Gasoline

• Natural gasoline is a mixture of pentanes and heavier hydrocarbons. It may also contain

small amounts of butanes.

• This product is sometimes call condensate. Natural gasoline is almost always shipped to a

refinery either as a separate stream or mixed in a crude oil stream.

• Vapor pressure control is important when it is blended with crude. Recently it has become

economical to feed natural gasoline to olefin crackers for petrochemical manufacturing.

NGL prices

NGL transportation

• In the mid 1940's Warren Petroleum began hauling propane from Houston to

Newark, NJ. This ocean going ship could carry 35 000 barrels of product.

• Today waterborn LPG shipments are critical to the international gas processing

industry. A typical long haul LPG carrier has four or five tanks and carries

350,000 to 550,000 barrels of product.

• The product is refrigerated to reduce the vessel design pressure.

NGL recovery economics

Liquid hydrocarbons are recovered from natural gas for three reasons:

1. NGL Product Recovery

• NGL recovery may be desirable if the market value of the various NGL components

in liquid product is greater than the sum of:

a. their equivalent heating value in the natural gas stream,

b. the cost to fractionate and transport the NGLs to market, and the cost to build and

operate a NGL extraction plant.

• NGL recovery under these circumstances is considered discretionary (i.e., a

recovery plant would not be built if it could not generate an adequate rate of return on

invested capital).

2. Maximize Liquid Production

• In many cases, no immediate market for the natural gas exists. Examples include

solution gas from remote crude oil reservoirs such as Prudhoe Bay, or retrograde gas

condensate reservoirs where the gas is re-injected for pressure maintenance, i.e.

cycling projects.

• In these cases, NGLs are frequently recovered and spiked into the crude or

condensate stream in order to maximize liquid production. NGL recovery levels are

set by the liquid product vapor pressure specification.

• For a TVP vapor pressure specification of 8-15 psia, NGL recovery is typically

confined to the C4+ components. This is strongly dependent upon the relative volume

of NGL to crude or condensate. NGL recovery under these circumstances is also

considered discretionary.

3. Hydrocarbon Dewpoint Control

• Virtually all gas sales contracts include a clause which limits the hydrocarbon

dewpoint of the gas. Typical values range from 14 to 41°F [-10 to 5 oC]. In order to

meet this provision of the contract, some type of NGL extraction is generally required.

• In many cases, the NGLs will be recovered for discretionary reasons, but in some

cases the only justification for the NGL plant is to meet the gas sales specifications.

In these instances, NGL recovery is mandatory since the gas could not be sold

without removal of the heavier NGL components.

• Recovery levels in these facilities are usually minimal with only a portion of the C5+

components being extracted.

The construction of a plant to recover NGL products is economically justified if the

cash flow generated by NGL recovery is incrementally more attractive than the

cash flow resulting from the current or future sale of those recoverable

components as part of the natural gas stream.

The economics of gas processing entails the margins, operating costs, and

capital costs. These items will be discussed below.

Margins

• Margins describe the revenue side of the plant economics. Depending on the

type of contracts, there may be gas, liquid, and/or processing fee margins (or

revenue).

• The gas margins and processing fees are straight forward. The calculation of

these revenue streams are describe in contracts and will not be discussed in

here.

• The liquid margins can be more difficult.

• If the processing contract is a percent of proceeds type, then the liquid margin

is calculated by splitting the liquid revenue received from the product sales (at

the plant) as established in the contract.

• The plant product sales price is sometimes called the netback price. This price

is the product price based at a market center less the transportation and

fractionation fees to move the NGLs to the market and separate the liquids into

final products. This netback price is the products value at the plant tailgate. In

addition, processors may charge producers a marketing fee for the disposition

of their NGLs.

• In keep-whole or flat rate contracts, the margins are based on the liquid

revenue less producer settlements calculated for the plant shrink. To calculate

the liquid shrink, the gallons of each product is converted to a gross heating

value.

Operating consts

• Factors such as company philosophies, plant configurations, plant utilization,

related services (gathering, compression, treating, etc.), contract terms,

electrical costs, etc. impact the operating costs. Therefore the best method for

determining the operating cost is from actual operations or from a budget "build-

up."

The major costs for operating a gas plant are listed below:

1. Fuel and Electricity.

• The fuel and power costs are usually the most significant cost to operate

recovery processes. This cost is typically associated with compression (inlet,

refrigeration, residue, recycle, etc.).

• Compressor power calculations can be performed through a number different

methods as discussed in Gas Conditioning and Processing - Vol. 2. An

approximation of power requirements is the "Rule of 22."

hp = 22 x F x n x CR x Qsc

hp = the compressor power

F = correction factor (1.00 single stage, 1.08 two stage, 1.10 three stage)

n = number of stages

CR = compression ratio per stage

Qsc = std volumetric flow (MMscfd)

The compression ratio per stage is

𝐶𝑅 =𝑛 𝑃𝑑𝑃𝑠

2. Labor

• The major consideration for labor cost is the operator coverage. This is

primarily a company operating philosophy, but guidelines can be provided.

There are four main types of shifts: 1) three 8 hour shifts, 2) two 12 hour shifts,

3) 8 hour attend (16 hour unattend), and 4) unattend. The first two shifts require

four personnel per shift-operator. The fourth person is required to rotate for

weekends, holidays, and vacation. The unattended operations, personnel

usually spend less than 4 hr/day at the plant.

• Unattended or 8 hour attend facilities are generally used for small gas plants

that are not critical to a companies operation. These plants typically do not

handle associated gas and sour gases. These types of plants are not usually

located near population centers.

• The product disposition can be by truck, rail, or pipeline provided the truck

loading is key-stop (automated) or the liquid production is low. The increased

use of SCADA for gathering makes this type of operation more attractive.

• For large plants, most facilities are attended 24 hours per day. Multiple

operators may be required if a significant amount of time is spent loading or

unloading trucks and tankers. Also multiple units (gas treating, compression,

utilities, etc.) may require multiple operators.

3. Maintenance.

• The maintenance budget is another major cost area. It is generally divided into

major maintenance and repair maintenance. Costs can be determined from

actual plant operations or vendors recommendations.

• Compressors are a significant factor in this budget. For electric motor driven

compressors, some people use $40-50/bhp-yr for budgeting purposes and $60-

70/bhp-yr for other compressors.

4. Chemicals and Operating Supplies.

• Chemicals may include lube oils, coolants, methanol, plant water, heat transfer

fluids, desiccant, glycols, filter elements, etc. These costs may be estimated

from typical usage and current pricing.

5. Other.

• There are other cost associated with gas plant operations. These include

royalties, taxes, insurance, general overhead and administration, etc.

Capital costs

• Gas sweetening process - absorption

• Gas dehydration process - TEG

• Mechanical refrigeration system with EG injection

• NGL fractionation

Gas processing plant in LNG FPSO

Construction in yard

Thank you!

• Liquid products may be classified into two general categories stock tank fluids

from separators and fractionated products.

1) The former is normally sold to a pipeline and is subject only to any pipeline limitations

such as BS&W, specific gravity, vapor pressure, and presence of "light ends."

: It is sometimes referred to as a "slop" product to distinguish it from those products

falling in the second category.

: In essence, the composition of this product will be fixed by the equilibrium

relationships at the pressure and temperature of the storage tank.

2) All other liquid products are a result of a fractionation which separates a raw mixture

into its component parts based on vapor pressure and other component physical

properties.

: These are commonly called natural gas liquids and are produced from what are

called NGL plants. If the effluent gas from an NGL plant is totally liquefied, it is called

liquefied natural gas (LNG).

• The amount of processing done at the production site depends on the amount

of fluids, available transportation to market, and local conditions.

• Offshore, swamps, jungle or arctic type locations limit the feasibility of more

complicated systems. The accent is on merely doing the least necessary at the

site to transport the production to more favorable surroundings for future

processing.

Example

• What is the liquid shrink from a 100 MMscfd turboexpander with the

following inlet gas composition and recoveries.

• The liquid shrink from recovering 268 461 GPD of NGL is 23 595 MMBtu/day.

Notice that the volume (scf/gal) is referenced to standard conditions of 60°F

and 14.696 psia.

• If the base conditions are different from standard conditions, then column C can

be corrected by the following equation.

𝐶𝐵 = 𝐶𝑆𝑃𝑆𝑃𝐵

𝑇𝐵𝑇𝑆

CB = volume corrected to base conditions

𝐶S = volume at standard conditions (60 oF, 14.69 psia )

P𝑆 = standard pressure, 14.69 pisa

P𝐵 = base pressure from contract, psia

𝐶𝐵 = standard temperature oR = 460 + 60 oF𝐶𝐵 = base temperature from contract, oR

• Also notice that the gross heating value can be calculated based on fuel as

liquid or as gas. The difference between these values is the latent heat of

vaporization. Using the gross heating value for fuel as a gas, benefits producers

in a keep-whole contract while processors are benefited by fuel as liquid GHV

values.

• In this example the effect is $87 M/yr at $1.50/MMBtu shrink value

• From these values we can also determine the breakeven price relationship

between recovery and rejection of individual components.

• This breakeven analysis does not include transportation and fractionation fees

and operating costs.

Shrinkage value of NGL products based on fuel as ideal liquid